The present invention relates generally to methods of ranking various formation stabilization treatments based on their ability to minimize formation damage using turbidity measurements of formation cuttings in different formation stabilizer solutions.
Maintaining wellbore stability is an important issue in the oil and gas industry. When a well is drilled, the formation around the wellbore must sustain the load that was previously taken by the removed formation. As a result, an increase in stress around the wellbore is produced. Wellbore stability is not only a mechanical problem. The interaction of chemicals in the treatment fluid with the formation also influences wellbore stability. There are various chemicals in the treatment fluid that can physically and chemically interact with the formations.
For example, formations containing clays are prone to water-sensitivity, which can cause damage to the formation through swelling, softening, and/or generation of migrating fines. The stability of the fracture-face of a formation depends on the sensitivity of the formation to water and other oilfield fluid components such as those used in fracturing. Fracture-face instability can result in proppant embedment, fines release, delamination, and extrusion. All of these can significantly reduce fracture permeability and decrease oil production.
Clays in the formation can swell, disperse, disintegrate or otherwise become disrupted in the presence of aqueous fluids. The swelling or dispersion of clays can significantly reduce the permeability of a formation and reduce mechanical strength of the formation. Some clays, in the presence of aqueous solutions, will expand and be disrupted to the extent that they become unconsolidated and produce particles that migrate into pore throats in the formation/proppant packs and reduce permeability/conductivity of the formation/fracture. In addition, many shales and/or clays are reactive with fresh water, resulting in ion exchange and absorption of aqueous fluids leading to loss of hardness of the rock in the formation.
Current approaches to determining formation stability involve examining rock mechanical properties using tests like the Quad cell embedment test or the Brinell hardness test to determine the best formation stabilizer to use in a formation. These traditional tests, however, require capital-intensive equipment, well-trained lab personnel, and core samples from each well at different depths. Obtaining core samples for each well and each zone of interest is typically very difficult. This problem is exacerbated by clay-rich layers being unstable for good core samples.
Typically formation stabilizers like inorganic salts and other cationic molecules are used to mitigate damage of water-sensitive formations caused due to the interaction of clays and/or other formation materials with aqueous fluids. However, there are no methods to efficiently and quickly determine the performance of formation stabilizers. Moreover, shales are highly heterogeneous formations which require specific formation stabilizers depending on the formation mineralogy.
Thus, there is a continuing need for improved methods for determining an optimum formation stabilizer for use in subterranean formations.